Determination of free water content, which may also be referred to as water fraction or water percentage, in a multiphase fluid mixture of water and crude oil is of great practical interest to the oil and gas industry, particularly from a point of view of corrosion monitoring and mitigation of the many pipelines which contain and serve to transport the flowing multiphase mixture.
The presence of free water in crude oil during transportation in offshore and onshore pipelines has been associated with accelerated corrosion rates in oil and gas production operations, particularly in the pipelines as well as associated equipment (e.g. valves) which make contact with the flowing mixture. Today, portable apparatus which offer rapid analysis of free water content in crude oil, particularly in deep-sea environments, are lacking.
Methods of analysis may include gravitational settling, centrifugation, thermal and cold treatments, microwave separation, ultrasonic separation, and separation under the action of an electric field (Samigullin and Khaziev, 2005). However, these methods may be considered labor intensive, time-consuming and require bulky equipment. As such, it is generally cumbersome to apply these methods in the field. As a result, there is a need for an apparatus to simply detect and measure free water content in a water and oil multi-phase mixture, for both offshore and onshore applications.
In addition to detection and measurement of free water content in crude oil, it is of critical importance to determine the properties of the free water in the multiphase mixture, such as its pH (potential Hydrogen). Accurate pH measurement of the water phase allows for more accurate selection of appropriate completion materials and effective planning for scale formation treatment and inhibition. Numerous corrosion predictive models are being developed to accurately predict corrosivity as a function of pH and other parameters of multiphase environments and define accurate limits of use of carbon steel pipes (Nesic et al., 2008). However, many of these models are overly conservative or focus only on a narrow range of parametric effects, thereby limiting their scope of applicability. Furthermore, for these models, pH is calculated from the CO2/H2S solution equilibrium.
There is a need to measure and validate the pH of free water phase in a crude oil and water multi-phase mixture in the field by using an apparatus which may measure such pH of free water in pipelines in-situ. A team led by Raghuraman (2007) developed a sensor that measures the pH of formation water at reservoir conditions in situ. Formation water may be understood as the water that is initially obtained during the oil extraction process. The sensor uses pH-sensitive dyes that change color according to the pH of the formation water. However, this sensor requires the implementation of several components typical of downhole optical fluid analyzers.